Various types of wellbore fluids are used in operations related to the development, completion, and production of natural hydrocarbon reservoirs. The operations include fracturing subterranean formations, modifying the permeability of subterranean formations, or sand control. Of particular interest with regard to the present inventions are fluids that could be used simultaneously for fracturing and controlling water applications during the life cycle of a hydrocarbon well, e.g., a well for extracting oil or natural gas from the Earth, wherein the producing well commonly also yields water. In these instances, the amount of water produced from the well tends to increase over time with a concomitant reduction of hydrocarbon production. Frequently, the production of water becomes so profuse that remedial measures have to be taken to decrease the water/hydrocarbon production ratio. As a final consequence of the increasing water production, the well has to be abandoned. If the formations are hydraulically fractured with the objective of increasing oil recovery, water production will also be increased, further reducing the productive life of the well.
The chemicals that can be used to modify the permeability of subterranean reservoirs, and hence the undesirable water production, must preferentially be easily pumped (i.e. have a low viscosity) so that they may be easily placed into the reservoir sufficiently far from the wellbore so as to be effective. It is also desirable for the chemicals or mixtures to reduce the permeability of the reservoir to flooding fluids (water) while simultaneously retaining most of the hydrocarbon permeability. Additionally, their placement should be selective in that they are placed into and reduce the permeability of flooding or driving fluids (water) without significantly affecting the less permeable strata. Numerous attempts at resolving these issues have been attempted over the years.
In many cases, a principal component of well water control fluids have been gelling compositions, usually based on polymers or cross-linked polymers. Water control fluids must selectively stop water production without detrimental effects to the oil production. Initially the preferred materials for this purpose were relative permeability modifiers (RPMs) such as polyacrylamide solutions. These polymers have long molecular chains that, after being injected, adhere loosely to the pore spaces, producing a drag on water production (resist water flow) without detrimental effects to the hydrocarbon (oil or gas) production. Unfortunately, these same compounds alone are shear sensitive and have their molecular weight (length of the chain) reduced when sheared, significantly affecting their ability to control/reduce water flow.
New generations of RPM materials have been developed that are less sensitive to shear and contain charged sites that could be adsorbed to the rock so that they remain in place for longer periods of time. These compounds are capable of reducing the relative permeability to water by 2 to 100 fold, depending on the differential pressure. However, for them to anchor properly to the rock these new RPM materials must be water wet and free of oil residues, owing to the fact that these fluids usually incorporate in their formulation a mutual solvent and water-wetting surfactants or detergents. Unfortunately, these compounds also are poor at controlling water in a fracture in heavy oil or asphaltenic crudes with deposits.
In attempting to improve water control down the wellbore and in the reservoir, it is important to understand the effects water has on the surrounding fluids. Water production is directly proportional to the mobility ratio of the formation fluids and therefore to their viscosities and relative permeability. Water at downhole conditions will have a viscosity ranging from 0.2 cps to 1 cps, depending on the well temperature. On the other hand, oil is encountered around the world with viscosities that could be as high as 5000 cps. Consequently, whenever the oil/water viscosity ratio is higher than 10, these RPM solutions become ineffective. In order to overcome this situation and improve water control, higher gel strengths have been suggested and pore blocking systems were developed (such as delayed cross-linked polymer solutions). However, these compounds have low viscosity while being pumped and develop high viscosity 3-dimensional gels over time.
Such pore-blocking systems could also preferentially block the oil-producing zone so they could not be used in fracturing treatments, therefore, to overcome this potential problem, rely on selective placement within the pore system for successfully blocking only the water production. This has been attempted at matrix rates (radial injection) by either mechanical methods when the water zone is known, or by reducing the viscosity of these fluids to water viscosity (very low polymer concentration) making the gel almost transparent to water so it can preferentially follow the water production paths in the reservoir instead of oil paths. Moreover, to achieve this and simultaneously obtain deep penetration into the reservoir, the fluids are pumped at very low injections rates (meaning that these treatments could last several days or even weeks). Unfortunately, sandstone formations are extremely heterogeneous, allowing these fluids to easily invade the oil-producing zone, blocking the pores with overall detrimental effects to oil or other hydrocarbon production.
Gels which are formed by polyacrylamide (U.S. Pat. No. 3,490,533) or polysaccharides (U.S. Pat. No. 3,581,524; U.S. Pat. No. 3,908,760; U.S. Pat. No. 4,048,079) with cations have been used as permeability modifiers for subterranean reservoirs. However, their application has been limited to reservoirs with low ambient temperature (less than 70° C.). Modifications of these compounds, such as sulfomethylated melamine gels (U.S. Pat. No. 4,772,641) have been made, but fail to address all of the needs of an effective well fracturing fluid. Additionally, numerous difficulties have been encountered with the use of such gel-forming chemicals, such as premature gel formation with concomitant plugging of the reservoir strata near the wellbore; decomposition of polyacrylamides and/or polysaccharides at elevated temperatures leading to destruction of gel character and loss of any permeability modifying attributes; and, over cross-linking and syneresis of the gel at elevated temperatures, thereby reducing the effectiveness of the gel as a permeability modifier.
Recently, the use of cross-linked gels that suffer controlled syneresis (gel contraction with extrusion of water) that partially unblock some of the pores spaces has been attempted. However, this effect happens in both water and oil pores, thereby eliminating any water control effect.
More recently, cationic viscoelastic surfactants such as N-erucyl-N,N-bis(2-hydroxyethyl)-N-methylammonium chloride (which exhibits oil wetting tendency in sandstones) have been frequently documented for application as an aid in water control in well fracturing fluids. This surfactant and similar surfactants are identified in U.S. Pat. No. 4,695,389, U.S. Pat. No. 4,725,372, U.S. Pat. No. 5,551,516, U.S. Pat. No. 5,964,295, and U.S. Pat. No. 6,194,356 B1. Unfortunately being cationic and oil wetting, some of the benefits are lost as detailed earlier.
In many cases, a principal component of wellbore fracturing fluids are gelling compositions, usually based on polymers and more recently on viscoelastic surfactants. The complete development of fracturing fluid and required properties are fully explained in SPE 37359 (Rae, P.; Di Lullo, G., “Fracturing Fluids and Breaker Systems: A Review of the State of the Art”, Soc. Pet. Engin., 37359, 1996).
The three dimensional gels produced by viscoelastic surfactants are preferred as well fracturing fluids when compared with other polymer linear or cross-linked gels even though they are more expensive because of their ability to support/transport solids at low viscosities and because they break cleanly (their viscosity reverts to that of water) in the presence of hydrocarbons, thus producing little or no damage to the sand pack (proppant pack) and to the formation rock, thereby yielding higher well production rates.
The viscoelasticity of the surfactant solutions appears and forms rapidly on mixing the various components which are usually mixed and proportioned continuously during the fracturing process. However, being shear thinning fluids they can be easily placed down the well. Viscoelastic gels are solid/polymer free fluids, and therefore their filtration into the formation matrix during the fracturing process is strictly dependent on the fluid leak-off viscosity. Fracturing fluids (irrespective of their chemistry) whose leak-off is controlled by viscosity, are less efficient than wall-building fluids, being at least one order of magnitude (10 times) worse than polymer based gels (which act to control their filtration process through polymer filter “cake” at the formation face). Thus, viscoelastic gels are relatively inefficient fracturing fluids and their use is limited to small and medium size fracture treatments. This could be overcome by the addition of solids or fluid loss control additives but with detrimental damaging effects to the sand/proppant pack. Another option could be the use of higher surfactant concentration to generate higher viscosities than those required to transport the sand/proppants at surface conditions, but this approach make the fluids very expensive and also surface handling or placement more difficult, especially when fluids are batch mixed. If this approach is acceptable, any application of viscoelastic surfactant gels that requires their transport or placement after their preparation would benefit from a method of controlling their viscosities, filtration properties, and gel times.
In addition to the reduced damage to the sand pack and to the rock, another possible benefit of using viscoelastic gels is controlling water production. Viscoelastic gels do not break easily in the presence of water, therefore any gel that infiltrated a water zone will maintain its viscoelastic properties, and being a shear thinning fluid under static conditions, will develop extremely high viscosities (over 10000 cps) that will block the pores and prevent water flow. However, another important factor in controlling water and hydrocarbon flow through a porous media is the wettability of the rock. Sandstone formation needs to be water wet for higher hydrocarbon flow, as oil wet sandstone rocks favor water flow. Cationic surfactants usually oil wet sandstone so the benefit obtained from blocking water in the water saturated pores are partly overcome by favoring water flow in the recently oil wet pores. Because viscoelastic surfactant properties/viscosity are affected by other chemicals (glycols, alcohols, mutual solvents and other surfactants but not limited to these families) it is quite difficult to overcome this detrimental oil wetting effect.
Thus, it can be seen that there is a need for improved compositions for wellbore water controlling fluids, especially fracturing fluids based on water wetting viscoelastic surfactants due to their higher hydrocarbon production potential (reduced formation damage) and to their potential water control properties. Moreover, it is desirable to reduce the viscoelastic gel filtration process of such compositions by either in-situ viscosity generation, or by the addition of water control chemicals or polymers that do not affect the viscoelastic properties of the gel and the rock oil relative permeability such as an RPM type material, in order to reduce the cost and allow for its application in bigger treatments. Providing such compositions with high and long lasting viscosity in the water-saturated pores and with water wetting properties in order to reduce water flow improves the oil/water ratio, and ultimately hydrocarbon (oil/gas) recovery, after fracturing operations within the hydrocarbon wells.